2016 ELECTRICITY SUPPLY PLAN FOR GHANA. An Outlook of the Power Supply Situation for 2016 and Highlights of Medium Term Power Requirements

Transcription

1 2016 ELECTRICITY SUPPLY PLAN FOR GHANA An Outlook of the Power Supply Situation for 2016 and Highlights of Medium Term Power Requirements January 2016

2 Executive Summary The power system in Ghana has been experiencing inadequate supply challenges since 2012 leading to load shedding. Efforts have been made by government and stakeholders in the power sector to resolve the power supply challenges. In line with this a number of additional generation projects are expected to come online by end of the year 2015 and early This report was prepared by a Technical Team from Energy Commission, GRIDCo and VRA. This report presents an outlook of power demand and supply for 2016 taking into consideration all the firm additional new projects and existing generation sources. It assesses the available hydro taking into consideration low reservoir elevations at Akosombo and provides the likely power supply situation for It gives an idea of the fuel requirements and associated cost and evaluates the power evacuation requirements for reliable power supply. It highlights the anticipated challenges and makes recommendations on the best course of action to ensure reliable power supply for The report further provides an outlook of the electricity demand and supply requirements for the next five years Demand Outlook The projected system peak demand for 2016 is 2477 MW which represents an 8.5% growth over the projected system peak demand for 2015 of 2,282 MW. The projected annual consumption for 2016 is 16,798 GWh which represents 8.7% growth over the 2015 projected annual consumption of 15,449 GWh Supply Outlook As a result of efforts to bring on additional generation capacity to curb the ongoing load shedding, a total installed generation capacity of 712 MW is expected to be online by the first quarter of The dependable capacity of the expected generation is 643 MW. The additional generation sources and their timelines are shown in the Table below. Plants Installed Capacity (MW) Dependable Capacity (MW) Fuel Type Remarks KTPP Gas/Diesel 100 MW in January, full output from March 2016 AMERI/VRA Gas Half capacity in February, full capacity in March TT2PP-X Gas Available from February 1, 2016 SAPP (2) Gas BXC Solar 20 0 Sunlight TOTAL (VRA&IPP) Gas turbine (120 MW) available from February, Full combined cycle (180 MW) available from March 20 MW capacity available from January 2016 at a capacity factor of 15%. 1

3 Based on plant maintenance programme for 2016 and an assumed average gas supply of 60 MMscf/day from Nigeria and 90 MMscf/day from Ghana fields the following are the key findings of the study: Hydro. The projected year start elevation at Akosombo in 2016 is feet. With this low elevation at Akosombo Generating Station, 3 units will have to be operated throughout the year in order to prevent a situation where elevations below 235 ft. will be recorded prior to the onset of the rains which will require operating only 2 units at Akosombo (a situation which will affect system stability). Kpong GS will be operated in tandem with Akosombo GS. This will result in a total annual generation of 3,910 GWh from Akosombo and Kpong GS. Bui GS is expected to generate about 926 GWh of energy by the end of This is based on the assumption that Bui GS will operate 2 units during the peak period for 10 hours/day/unit from January to end of June For the second half of the year it is projected that Bui GS will operate 2 units for 12 hours/day/unit from July to the end of December Thermal. The total expected annual thermal generation in 2016 is 11,565 GWh representing 70.51% of total energy supply for About 30 GWh (0.16%) is also expected to be supplied from solar power. Thus a total supply of 16,448 GWh is expected in The remaining 396 GWh will have would have to be shed mainly during the first two months because of expected supply deficit in January and February The Ghana power system will have low reserve margin in 2016 and therefore when units are out for maintenance the system will be prone to inadequate supply. Fuel. The gas supply quantities from Ghana fields and Nigeria fields are inadequate for all thermal plants to run on gas. Consequently the KTPP plant would have to be operated on diesel, while the T1, TT1PP and CENIT plants will operate mainly on LCO. The T2 plant will operate mainly on gas with LCO as supplement. The Karpower barge is expected to operate on HFO. In all a total of about 5.9 million barrels of LCO will be required in About 4.3 million barrels would be required for the VRA power plants and about 1.6 million barrels for non-vra plants. An estimated 1.4 million barrels of diesel will be required by the KTPP plant. One crucial requirement for reliable power supply is the availability of the required quantities of fuel and funds to purchase the fuel in a timely manner. This is critical because Akosombo GS that used to make-up for shortfalls in thermal generation will have to be restricted to three (3) units operation in Based on assumed quantities of natural gas expected from Nigeria and Ghana fields an estimated US$ billion will be required to purchase LCO, Natural Gas, HFO and diesel 2

4 to run the thermal plants. About US$ million will be required by VRA and about US$ million will be required by the IPPs. Sensitivity analysis on fuel cost indicates that for a US$10/barrel reduction in the cost of LCO and its corresponding decrease in diesel and HFO prices plus a US$ 1/MMBtu reduction in natural gas price of WAGP and Ghana, the total annual reduction in fuel cost was US$ million. Similarly a US$ 1/MMBtu reduction in the price of Ghana gas without a corresponding reduction in any of the other fuel costs, a total annual fuel cost reduction of US$ million is recorded. Power Evacuation. The transmission system has inadequate firm transfer capability to some of the major load centres (of Accra, Kumasi, Tarkwa, etc.) mostly at peak. This situation results in low voltages, overloading of lines and increase in transmission system losses. A significant percentage of network loads are islanded in the event of outage on some radial lines. 1. To ensure stability of the grid, a minimum generation required to be in operation at all times is as follows: o 300 MW power generation from Aboadze and o Three (3) Akosombo units (3x125MW) Voltages at Kumasi, Accra and surrounding areas are low because of poor customer end power factors. Generation scheduling has significant impact on system losses. System losses are lower with maximum generation at the west compared to losses with maximum generation at the east. Medium Term ( ) Power Requirements. Over the medium term a total of about 1,200 MW (3 x 340 MW MW) additional generation capacities is required to ensure that the power system has a minimum of 25% reserve margin. We should therefore commence work to ensure that the additional 1,200 MW (3 x 340 MW+180 MW) of generation capacity required over the period are added unto the Ghana power system in a timely manner (2017, 2019, 2021) to assure reliable power supply 3

5 Table of Contents 1.0 INTRODUCTION DEMAND OUTLOOK FOR Capacity Demand Outlook Outlook of Energy Consumption SOURCES OF ELECTRICITY SUPPLY IN Sources of Generation Existing Generation Sources a. Existing Hydroelectric Generation Sources b. Thermal Generation Facilities Additional Generation Sources Key Assumptions Projected Demand Available Quantities of Gas Fuel Allocation Fuel Price Planned Maintenance Projected Supply Outlook Projected Capacity Situation Contingency Analysis Fuel Requirement Fuel Cost Sensitivity Analysis on Cost of Fuel TRANSMISSION SYSTEM OUTLOOK State of Ghana National Interconnected Transmission System

6 4.2 Availability of Transmission Lines, Feeders and Substations System Analyses - Steady State Summary of System Analysis Results Transmission System Constraints Recommended System Expansion & Upgrade to Address Network Constraints ELECTRICITY SUPPLY CHALLENGES ELECTRICITY SUPPLY OUTLOOK Projected Demand Outlook ( ) Projected Supply Outlook ( ) Existing Generation Committed Generation Additional Generation Requirement CONCLUSIONS RECOMMENDATIONS

7 1.0 INTRODUCTION The Ghana power system has been experiencing supply challenges since Efforts by government and stakeholders in the power sector have been made to resolve the power supply challenges. In line with this Karpowership Ghana Ltd commissioned a 250MW power barge into operation in December 2015 while a number of additional generation projects are expected to come online early However Akosombo hydroelectric generating station, which is the biggest generating station in the country is recording very low reservoir elevations require its output in 2016 to be limited. This report presents an outlook of electric power demand and supply for 2016 taking into consideration existing generation sources as well as all firm new additional generation projects. It assesses the available hydroelectric capacity for 2016, taking into consideration current low elevations at Akosombo and provides an outlook of the likely power supply situation. It provides a forecast of the fuel requirements and the associated fuel costs. It also evaluates the requirements for reliable transmission/evacuation of electric power from the sources of supply to the load centers across the country, highlights the anticipated challenges and makes recommendations on the best course of action to ensure reliable power supply for The report further provides an outlook of the electricity demand and supply requirements for the next five years. The report was prepared by a team comprising experts from Energy Commission, GRIDCo and VRA. The team consulted all the power producers in the sector and other key stakeholders to firm up maintenance programmes, new projects and other relevant information required for the analysis. The team extensively reviewed the power supply situation and agreed on the most likely situation in 2016 and agreed on the key assumptions for the study. Chapter 1 of the report is the Introduction, while Chapter 2 presents the electricity demand outlook for Chapter 3 focuses on power supply and the associated fuel requirements. Chapter 4 presents the evacuation issues and Chapter 5 highlights the anticipated challenges. Chapter 6 provides an outlook for the next 5 years after Finally, Chapter 7 draws conclusions on the report and Chapter 8 presents recommendations on the way forward. 6

8 2.0 DEMAND OUTLOOK FOR Capacity Demand Outlook The projected Base Case coincident peak demand for year 2016 is 2,477 MW, which represents an 8.5 % growth over the 2015 projected peak demand of 2,282 MW. This assumes one potline operation at VALCO in Table 1: Summary of 2016 Projected Demand Demand Customer 2016 Estimated Coincident peak Demand (MW) Domestic Consumption Exports ECG 1,617 NEDCo 185 Mines Direct Customers New Obuasi Obuasi New Tarkwa Prestea Ahafo/Kenyase (Newmont) New Abirim (Newmont) Akyempem (Wexford) Ayamfuri (Central Ashanti) Bogosu Akwatia Konongo Adamus Gold Akosombo Textiles Aluworks Ghana Water Company Ltd Enclave Power Company Diamond Cement Generation Plants Station Service Volta Hotel Savana Cement (Buipe) VRA Townships 246 Losses + Network Usage 106 Total 2,250 CEB CIE SONABEL Total VALCO 74 Peak Demand MW 2, It is worth noting that, due to supply deficits in 2015, available generation capacity was not adequate to realise the projected peak demand for the most part of the year. The highest allyear demand of 2188 MW recorded in 2015 is therefore a constrained peak demand. The peak demand for 2016 was therefore derived basing on the projected peak demand for

9 Factors which are projected to contribute to the growth in demand are: 1. Expected increases in spot loads, prominent among them are: i. Western Diamond Cement 7 MW (ECG, Takoradi); ii. Ghana Water Company Kpong 25 MW; iii. Enclave Power Authority - 42 MW; iv. Asanko Gold 17 MW; v. Rice Factory at Nyankpala MW; vi. GWCL in Wa MW; and vii. Aluminium Company in Tamale MW etc. 2. On-going network expansion works and measures to improve the quality of distribution services by ECG and NEDCO are also expected to allow the connection of new loads which would result in an increase in demand in the residential, commercial and industrial sectors. 3. The numerous rural electrification projects earmarked for commissioning in 2016 are expected to lead to demand increases on both the ECG and NEDCO distribution networks. Figure 1 shows system peak demand for 2016 by customer, ECG demand constitutes 64% of the total system peak followed by Mines 10%. VALCO at one potline represents 3%, NEDCO 8%, Exports to CEB and SONABEL 6%. DIRECT 4% 2016 Projected Demand (MW) Export VALCO 6% 3% System Usage 4% MINES 10% NEDCo 8% ECG 65% Figure 1: System Peak Demand for 2016 by Customer 8

10 2.2 Outlook of Energy Consumption The total expected energy consumption for 2016 is 16,798 GWh (this includes suppressed demand of 7.5%). This figure includes estimated transmission system losses of 4 % of total energy generation. The projected 2016 energy demand represents a growth of approximately 8.7 % over the projected 2015 figure of 15,449 GWh. It should also be noted that the 2016 projected growth in consumption includes the energy that was not served in 2015 and it assumes VALCO operating at one Potline. The summary of 2016 estimated energy consumption is presented in Table 2. Table 2: Summary of projected 2016 Energy Consumption Energy Customer 2016 Estimated Consumption (GWh) ECG 10,778 Domestic Consumption NEDCO 1,285 Mines 1,813 Direct Customers 582 Network Usage 8 Losses 631 Total Domestic 15,097 CEB 1,000 Total Exports CIE 18 SONABEL 63 VALCO 620 Total Energy 16,798 As shown in Figure 2, ECG s consumption is the highest of all the customer groupings constituting about 64% of the total energy consumption for the year 2016, it is followed by the mines with a projected consumption of 11% Projection Energy Consumption (GWh) VALCO Exports SYSTEM USAGE 4% 6% 4% DIRECT 3% MINES 11% NEDCo 8% ECG 64% Figure 2: 2016 Projected Energy Consumption by Customer 9

11 3.0 SOURCES OF ELECTRICITY SUPPLY IN Sources of Generation The sources of generation considered are the generation facilities existing as at December 2015 and the committed and firmed generation projects expected to begin operations in Existing Generation Sources a. Existing Hydroelectric Generation Sources Akosombo GS and Kpong GS 2015 inflow season for the Volta Lake ended with an Akosombo reservoir maximum elevation of ft. Akosombo reservoir elevation on January 1, 2015 was ft. and operated mainly 4 units during off-peak period and 5 units during the peak period. There were some occasions that 5 units were operated throughout the day. The reservoir elevation at Akosombo GS dropped by ft. to a minimum elevation of ft. on August 14, 2015 before the onset of the inflow season. At the end of the inflow season, the maximum elevation attained was ft. The total rise in elevation recorded after the inflow season was 7.71 ft. whiles the year start elevation for 2016 was ft. (which is 4.51 ft. lower than the 2015 year start elevation of ft.). This year start elevation is only 2.62 ft. above the Minimum Operating Level (MOL) of ft. and 7.4 ft. above the Extreme Minimum Operating Level (EMOL) of ft. The Akosombo reservoir trajectory for 2015 is shown in Figure Akosombo Reservoir Trajectory Figure 3: 10

12 In the light of the poor inflows in 2015 and with the very low reservoir level, there is a limitation on the amount of electric energy that can safely and reliably be generated from the Akosombo hydropower station. Based on analysis conducted, the Akosombo reservoir can support only 3 units operation which will lead to a minimum elevation of 235 ft. at the end of July Challenges with 2 Units Operation at Akosombo: It is extremely important that the Akosombo GS be STRICTLY limited to operate with only three (3) units running at all times in 2016 from January 1, 2016; this will be prudent towards managing the rate of depletion on the reservoir so that the Extreme Minimum Operating Level (EMOL) of 235 ft. is reached only at the end of July 2016 when the next inflow season is expected to begin. Below elevation 235ft., the design of the penstock intake is such that only two units (unit nos. 3 and 4) which have lower intake levels could be put in operation at Akosombo. There are two key reasons why it is CRITICALLY necessary to ensure the reservoir level does not drop below 235 ft. where only two (2) units at Akosombo would be operable: 1. First, it is worth noting that to date, generating units in operation at Akosombo GS are solely responsible for load following and real-time primary frequency control on the Ghana power system. Furthermore, it is of great importance to note that two (2) units at Akosombo GS cannot alone effectively carry out the entire load-following burden on the Ghana power system, considering its present size. A minimum of three (3) units at Akosombo are required in operation at all times to effectively do this. 2. Secondly, with only two (2) units in operation at Akosombo GS, the power system shall suffer steady-state stability problems such that it can easily experience system collapse with minimal disturbance in the power system. It is therefore expedient that strict measures are put in place to resist every temptation to put more than three (3) units in operation at the plant in order to manage the rate of depletion of the head water in the dam so that elevations lower than 235 ft. are not recorded before the onset of the rainy season in At current low elevations at Akosombo the average reliable capacity on a unit at Akosombo is 125 MW. Hence operating three units at Akosombo will mean an average capacity of 375 MW will be available for dispatch from Akosombo GS in Kpong GS which is currently undergoing retrofit will largely have three (3) out of the four (4) units available. The total average capacity that will be available at Kpong GS will therefore be 105 MW at an average capacity of 35 MW/unit. This mode of operation at Akosombo and Kpong generating stations in 2016 will lead to a projected annual cumulative generation of 3,910 GWh from the two plants. The projected trajectory for the Akosombo reservoir in 2016 assuming three (3) units operation is as shown in Figure 4. The projected minimum elevation at the end of the dry season in July 2016 is 235 ft. 11

13 NOTE: In the event that the beginning of the inflow season delays in 2016 (as it did in 2015), there is a risk of going below 235 ft. at Akosombo GS even with the recommended mode of operation. The projected Akosombo reservoir trajectory for 2016 is shown in Figure 4. Figure 4: Akosombo Projected Trajectory for 2016 Bui Hydro In 2015, the Bui hydroelectric generating station typically operated two (2) units during the peak period for a greater part of the year. However during a greater part of the first quarter of 2015, Bui had one (1) unit in operation during the off-peak periods. In this mode of operation Bui generation station is produced GWh at the end of this year Bui started the year at about elevation metres (m). Bui s elevation as at November 16, 2015 was m. The designed maximum elevation at Bui hydro station is 183 m. Bui hydropower station reservoir trajectory for 2015 is as shown in Figure 5. In 2016, it is projected that Bui generation station will produce about 926 GWh of electricity. It is assumed that Bui GS will operate 2 units during the peak period for 10 hours/day/unit from January to end of June For the second half of the year it is projected that Bui will operate two (2) units for twelve (12) hours/day from July End of December This mode of operation will result in the projected annual production of 926 GWh at the end of the year. 12

14 Figure 5: Bui Reservoir Trajectory for 2015 b. Thermal Generation Facilities The total installed capacity of existing thermal generation facilities is 1,459 MW of which 1,340 MW is dependable capacity. Of the existing thermal generation as of December 2015, 1295 MW is available for dispatch in It is assumed here that in 2016, all existing thermal generation facilities would remain available. The installed, dependable and available capacities of existing generation sources assumed for the 2016 Electricity Supply Plan are as shown in Table 3. From Table 3, the total installed capacity of the existing generation sources is 3,042 MW of which 2,720 MW is the dependable capacity. The total available capacity of the existing generation sources for 2016 is therefore 2,055 MW. Table 3: Existing Generation Sources as of December,

15 Plants Installed Capacity (MW) Dependable Capacity (MW) Available Capacity (MW) Fuel Type Availability Factor (%) Akosombo GS Water 85% Kpong GS Water 72% TAPCO (T1) LCO/Gas 85% TICO (T2) LCO/Gas 85% TT1PP LCO/Gas 88% TT2PP Gas 85% MRP Gas 80% VRA Solar Plant Sunlight 18% TOTAL VRA SAPP Gas 92% CENIT LCO/Gas 92% Karpower HFO/Gas 92% Bui HEP Water 85% TOTAL (VRA&IPP) Additional Generation Sources Based on efforts to bring on additional generation capacity to curb the ongoing load shedding, a total generation capacity of 712 MW is expected to be installed and put into operation by the end of the first quarter Of this additional capacity expected to be installed, the dependable capacity is expected to be 643 MW. The timelines for installation of the additional generation projects showing details of their installed and dependable capacities are shown in Table 4. 14

16 Table 4: Expected Additional Generation Sources in 2016 Plants Installed Capacity (MW) Dependable Capacity (MW) Fuel Type Availability Factor (%) KTPP Gas/Diesel 85% VRA/AMERI Gas 90% TT2PP-X Gas 85% SAPP (2) Gas 85% BXC Solar 20 0 Sunlight 15% TOTAL (VRA&IPP) Remarks 100 MW in January and February, Full output from March 2016 Half capacity in February, full capacity in March Available from February 1, 2016 Gas turbine (120 MW) available from February, Full combined cycle (180 MW) available from March 20 MW capacity available from January 2016 at a capacity factor of 15%. 3.2 Key Assumptions The supply plan was developed on the basis of assumptions made in the following areas: Projected demand Planned Maintenance Available quantities of gas Fuel Allocation Fuel Prices Projected Demand Projected demand is based on GRIDCo s electricity demand projection for The projected annual peak electricity demand is 2,477 MW and the projected annual consumption is 16,798 GWh. Generating facilities would therefore be dispatched to meet the estimated demand for Table 5 summarizes the projected demand for

17 Table 5: Projected Demand Customer Category Projected Demand GWh MW ECG 10,778 1,617 NEDCO 1, Mines 1, Other Direct Customers Total Domestic 14,457 2,144 Valco Exports (CEB+SONABEL+CIE) 1, Transmission & Network Losses Total 16,798 2, Available Quantities of Gas Two main sources of natural gas supply were considered as follows: Nigeria Gas Average supply of 60 mmscf/day is assumed from January December Ghana Gas Average supply of 90 mmscf/day is assumed from January December Fuel Allocation In the light of the projected limited quantities of natural gas supply, fuel allocation at Tema and Takoradi enclaves were as follows: Tema: All Gas supply from Nigeria is assigned to the existing and new Sunon-Asogli power plants; TT1PP/CENIT runs on LCO; KTPP runs on diesel; Karpower Barge runs on HFO; MRP/TT2PP/TT2PP-X are on standby. Takoradi: Ghana Gas supply is assigned to TAPCO, AMERI and partly to TICO power plants; TAPCO operates mainly on LCO with gas as supplement; TICO operates mainly on gas with LCO as supplement Fuel Price The following assumptions on delivered fuel price were made: 16

18 Nigeria Gas US$ 9.0/mmbtu Ghana Gas US$ 9.0/mmbtu LCO US$ 60/barrel Diesel US$ 90/barrel 1.5 x LCO price) HFO US$ 72/barrel (@ 1.2 x LCO price) Planned Maintenance The key maintenance activities expected to be undertaken in 2016 on the various plants are as shown in Table 6: Table 6: 2016 Planned Maintenance Plants Akosombo GS Planned Maintenance Akosombo maintenance is not expected to impact on supply since only 3 units will be expected to be dispatched Kpong GS TAPCO TICO TT1PP TT2PP MRP VRA Solar Plant SAPP CENIT Bui HEP Kpong major retrofit is ongoing. Major unit inspection for 2 weeks will be carried out on 1 unit at a time in February and July 2016 Fuel Nozzle Inspection on Unit 1 in March for 1 week Major Inspection on Unit 2 (3 rd April 15 th May) Minor Inspection on Steam Turbine (19 th June 10 th July) Hot Gas Path Inspection on Unit 1(5 th November 2 nd December) Warranty Inspection on Steam Turbine (5 th November 2 nd December) Major Inspection in January (1 month) Major Inspection (6 th June 24 th July) Core Engine Swap and main gearbox overhaul on Unit 1 (1 14 August) Core Engine Swap and main gearbox overhaul on unit 2 (4 17 July) Each of the 3 units will undergo maintenance for 4 days in March, June, September and December Maintenance will not impact on supply Hot Gas Path Inspection on 1 unit (20 th February 12 th March) Major Inspection on Steam turbine (28 th March 6 th May) Major Inspection on gas turbine (28 th March 28 th April) Combustion Inspection (17 27 April) Combustion Inspection in February & July for 7 days each. Maintenance will not impact on supply 17

19 Projected Supply Outlook Based on the above assumptions and the projected plant generation the summary of demand/supply balance for 2016 is shown in Table 7. Table 7: 2016 Projected Demand/Supply Balance Demand/Supply Projected Demand/Supply (GWh) Total ECG 10,778 NEDCO 1,285 Mines 1,813 Other Customers 582 Total Domestic 14,458 Valco 620 Exports (CEB+SONABEL+CIE) 1,081 System Usage & Losses 639 Total Projected Demand 16,798 Projected Supply Total VRA Hydro (Akosombo & Kpong GS) 3,910 Bui GS 926 VRA Existing Thermal & Solar Generation Takoradi 1 (T1) 2,109 TT1PP 472 MRP - TT2PP 13 VRA Solar Power Plant 4 Total VRA Thermal Generation 2,598 Existing IPP Thermal Generation Sunon-Asogli (SAPP) 1,275 CENIT Power Plant 694 Takoradi 2 (T2) 2,071 IPP Thermal Generation 4,040 New Generation Projects TT2PP-X (VRA) 10 KTPP (VRA) 712 VRA/AMERI (VRA/IPP) 1,592 SAPP - X (IPP) 1,138 Karpower Barge 1 (IPP) 1,449 Central Region Solar Project (IPP) 26 Total Supply from New Generation 4,927 Total VRA Supply 8,822 Total Non-VRA Supply 7,579 Total Supply 16,402 Projcted Annual Consumption 16,798 Projected Supply Deficit (GWh)

20 From Table 5, there is a projected supply deficit of 350 GWh which occurs mainly in January and February 2016 because of the timing of the new projects. From March 2016 it is expected that if there is sufficient fuel for running the thermal plants then there should be enough generation to meet projected demand. The monthly supply projections are shown in Table 8. 19

21 Table 8: Projected Monthly Generation PROJECTED DEMAND AND SUPPLY Jan Feb Mar Apr May Jun Jul Aug Sept Oct Nov Dec Total PROJECTED DEMAND ,798 PROJECTED SUPPLY Hydro Supply Hydro Draft Rate (GWh/day) Akosombo GS (GWh) ,285 Kpong GS (GWh) Total Akosombo and Kpong Hydro Generation (GWh) ,910 Bui GS (GWh) Thermal Supply (GWh) Projected T1 - Combined Cycle (LCO/Gas) ,109 T2 - Combined Cycle (LCO/Gas) ,071 TT1PP - Simple Cycle (LCO/Gas) TT2PP (Gas) MRP (Gas) Sunon-Asogli Power Plant (Gas) ,275 CENIT Power Plant (LCO) VRA Solar Power Plant TT2PP-X (Gas) KTPP - Simple Cylce (Gas) KTPP - Simple Cylce (Diesel) VRA/AMERI Power Plant ,592 Karpower ,449 Sunon-Asogli (Phase 2) ,138 Central Region Solar Plant (20 MW) Imports from Cote d'ivoire Total Thermal Supply (GWh) ,043 1,012 1, ,016 1,015 1,057 11,565 Total Supply (GWh) 1,094 1,259 1,445 1,402 1,435 1,355 1,372 1,364 1,352 1,433 1,419 1,474 16,402 Add. Supply Required (GWh) Add. Supply Required (MW)

22 3.4 Projected Capacity Situation Taking planned maintenance and fuel constraint on MRP, TT2PP and TT2PP-X into consideration the projected monthly capacity situation is as shown in Table 9. Table 9: Projected Monthly Capacity Situation for Projected System Peak (MW) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Domestic ,104 2,081 2,099 2,135 2,138 2,122 2,056 2,051 2,131 2,109 2,175 2,250 VALCO Export (CEB+SONABEL) Projected System Demand ,331 2,308 2,326 2,362 2,365 2,349 2,283 2,278 2,358 2,336 2,402 2,477 Dependable Generation Sources Capacity (MW) Akosombo GS Kpong GS T T TT1PP TT2PP MRP KTPP VRA/AMERI Power Plant TT2PP-X VRA Solar Total VRA Availabe Generation ,230 1,223 1,630 1,480 1,480 1,530 1,395 1,470 1,630 1,630 1,630 1,630 Karpower Barge SAPP SAPP (Phase 2-Stage 1) CENIT Bui GS Solar (Central Region) Total Available Generation (MW) ,940 2,078 2,445 2,350 2,395 2,445 2,210 2,385 2,545 2,545 2,545 2,545 Capacity Out of Service (MW) 1,228 1, Generation Reserve Capacity (MW) (391) (230) 119 (12) (73) Reserve Margin 35% -17% -10% 5% -1% 1% 4% -3% 5% 8% 9% 6% 3% From Table 9, generation capacity deficits are recorded in January, February and April. From May (except July) the capacity situation improves. However reserve margins are very low such that an outage to any unit assumed to be in operation within the period (or a sudden variation in projected demand) could lead to supply challenges Contingency Analysis Contingency analysis was carried out to determine the impact of one of the most likely scenarios of losing one gas turbine and the associated steam generation at Takoradi due to either a fault or gas supply curtailment in any given month. This will constitute the loss 150 MW of generation capacity. The results of the contingency analysis indicates that in all the months except September and October the loss of 150 MW generation capacity at Takoradi has a very adverse impact on supply reliability. This buttresses the point that the inadequate generation reserve capacity will 21

23 be a major challenge to reliable power supply in The results of the analysis is illustrated in Table 10. Table 10: Results of Contingency Analysis on Loss of 150 MW Generation Capacity at Takoradi 2016 Projected System Peak (MW) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Domestic ,104 2,081 2,099 2,135 2,138 2,122 2,056 2,051 2,131 2,109 2,175 2,250 VALCO Export (CEB+SONABEL) Projected System Demand ,331 2,308 2,326 2,362 2,365 2,349 2,283 2,278 2,358 2,336 2,402 2,477 Dependable Generation Sources Capacity (MW) Akosombo GS Kpong GS T T TT1PP TT2PP MRP KTPP AMERI Power Plant TT2PP-X VRA Solar Total VRA Availabe Generation ,080 1,073 1,480 1,330 1,330 1,430 1,295 1,320 1,480 1,480 1,480 1,480 Karpower Barge SAPP SAPP (Phase 2-Stage 1) CENIT Bui GS Solar (Central Region) Total Available Generation (MW) ,790 1,928 2,295 2,200 2,245 2,345 2,110 2,235 2,395 2,395 2,395 2,395 Capacity Out of Service (MW) 1,378 1, , Generation Reserve Capacity (MW) (541) (380) (31) (162) (120) (4) (173) (43) (7) (82) Reserve Margin 35% -23% -16% -1% -7% -5% 0% -8% -2% 2% 3% 0% -3% 3.5 Fuel Requirement In 2016 Light Crude Oil (LCO), Natural gas, diesel and Heavy Fuel Oil (HFO) are the types of fuel that will be required for firing thermal generating plants on the Ghana power system. The quantities of the various types of fuel required are presented as follows: LCO. The total LCO requirement for 2016 is about 5.9 million barrels of which about 4.3 million barrels would be required for the VRA power plants and about 1.6 million barrels for non-vra plants. Based on a cargo size of 405,000 barrels, the annual LCO cargo requirement for VRA plants is about 10.5 cargoes and 4 cargoes for the CENIT plant. Thus a total of 14.5 cargoes of LCO would be required. Natural Gas. Based on the projected average supply of 60 mmscf/day and 90 mmscf/day from Nigeria and Ghana respectively, the total natural gas consumption is projected to be about 54.4 billion mmbtu. An estimated 18.2 billion mmbtu would be used by VRA plants and 36.2 billion mmbtu will be used by IPPs. 22

24 HFO. HFO would be used mainly by the Karpower Barge. An estimated 2.8 million barrels would be required. This translates to 6.8 cargoes, assuming a cargo size of 405,000 barrels. Diesel. Diesel would be used mainly by the KTPP plant and for start and stop of all thermal plants. An estimated 1.4 million barrels (3.4 cargoes for a cargo size of 405,000 barrels) would be required by KTPP for power generation. An estimated 60,164 barrels would be required for starting and stopping all VRA thermal power plants. Another 51,140 barrels of diesel is estimated to be used by IPPs for starting and stopping of the plants. 23

25 Table 11: Monthly Fuel Requirement and Cost Projected Jan Feb Mar Apr May Jun Jul Aug Sept Oct Nov Dec Total Estimated Thermal Fuel Requirements LCO T1 -Combined Cycle (bbls) 0 185, , , , , , , , , , ,365 2,675,187 T2 - Combined Cycle (bbls) ,953 59,954 61,643 59, ,953 59,954 61, , ,095 Total LCO Requirements (bbls) - TTPS 0 185, , , , , , , , , , ,405 3,150,282 Additional Generation LCO TT1PP (bbls) , , ,124 29,630 34,568 93,409 94, , , ,762 1,096,694 CENIT (bbls) 159, , , , , , ,206 99, ,508 92, , ,142 1,612,852 Total LCO Requirements (bbls) 0 185, , , , , , , , , , ,167 4,246,976 Diesel & HFO Diesel for start & Stop (All VRA Plants) 5,096 4,767 5,096 4,932 5,096 4,932 5,096 5,096 4,932 5,096 4,932 5,096 60,164 KTPP (Diesel) 0 137,547 58, ,546 86,490 83, ,312 86,490 83,700 86, ,427 86,490 1,297,549 Total DFO Requirements (bbls) 5, ,314 63, ,477 91,586 88, ,408 91,586 88,632 91, ,358 91,586 1,357,714 Diesel for start & Stop (other plants) 4,332 4,052 4,332 4,192 4,332 4,192 4,332 4,332 4,192 4,332 4,192 4,332 51,140 Karpower HFO 253, , , , , , , , , , , ,291 2,745,807 GAS Requirements (MMBtu) T1 -Gas Turbines (MMBtu) 1,442, , , , ,885,485 T2 -Gas Turbines (MMBtu) 786,343 1,427,980 1,224,971 1,185,456 1,224,971 1,185, ,343 1,224,971 1,185,456 1,224, ,897 1,224,971 13,312,782 TT1PP - Simple Cycle (MMBtu) MRP (MMBtu) TT2PP (MMBtu) 28, , ,336 TT2PP-X (MMBtu) 0 124, ,680 Sunon-Asogli (MMBtu) 1,085, ,623 1,074, ,596 1,074,559 1,039,896 1,074,559 1,074,559 1,039,896 1,074,559 1,039,896 1,074,559 11,894,773 KTPP (MMbtu) 746, , , ,678,104 Sunon-Asogli Phase 2(MMBtu) 0 734, , , , , , , , , , ,441 8,095,108 VRA/AMERI (MMbtu) 0 732,030 1,565,029 1,514,544 1,565,029 1,514,544 1,565,029 1,565,029 1,514,544 1,565,029 1,514,544 1,565,029 16,180,384 Total Gas Consumption 4,088,651 4,350,000 4,650,000 4,500,000 4,650,000 4,500,000 4,650,000 4,650,000 4,500,000 4,650,000 4,500,000 4,650,000 54,338,651 Total VRA LCO Cost (US $ Million) Total VRA Diesel Cost (US$ Million) Total VRA Gas Cost (US$ Million)-Ggas Total VRA Gas Cost (US$ Million)-WAGP Total VRA Fuel Cost (US$ Million) IPP Fuel Cost AMERI Gas (US$ Million) CENIT LCO (US$ Million) SAPP Gas (US$ Million) Karpower HFO (US$ Million) Total IPP Diesel Cost (US$ Million) Total IPP Fuel Cost (US$ Million) TOTAL FUEL COST (VRA+IPP) ,

26 3.6 Fuel Cost The total estimated fuel cost for 2016 is US$ billion of which about US$ million will be required by VRA and about US$ million will be required by the IPPs. This translates to an average fuel cost of about US$97 million/month. From Table 11 above the breakdown of the cost is summarized in Table 12: Table 12: Breakdown of Estimated Fuel Cost for 2016 VRA Fuel Cost Cost (US$ Million) Total VRA LCO Cost (US $ Million) Total VRA Diesel Cost (US$ Million) Total VRA Gas Cost (US$ Million)-Ggas Total VRA Gas Cost (US$ Million)-WAGP Total VRA Fuel Cost (US$ Million) IPP Fuel Cost VRA/AMERI Gas (US$ Million) CENIT LCO (US$ Million) SAPP Gas (US$ Million) Karpower HFO (US$ Million) Diesel for Start & Stop 4.60 Total IPP Fuel Cost (US$ Million) Total VRA & IPP Fuel Cost (US$ Million) 1, Sensitivity Analysis on Cost of Fuel Sensitivity analysis was conducted to check the impact of a reduction in price of liquid fuel and natural gas. LCO price was reduced by US$10/barrel to US$ 50/barrel. This translated into a corresponding diesel price of US$ 75/barrel and HFO price of US$ 60/barrel. Additionally natural gas price of WAGP and Ghana gas were reduced by US$ 1/MMBtu each from US$ 9.0/MMBtu to US$ 8.0/MMBtu. 25

27 The results of the sensitivity analysis indicates that the total annual reduction in fuel cost was US$ million. Additionally sensitivity analysis was conducted to assess the impact of a reduction in the price of only gas supply from Ghana fields. The results of the sensitivity analysis indicates that for a US$ 1/MMBtu reduction in the price of Ghana gas without a corresponding reduction in any of the other fuel costs, a total annual fuel cost reduction of US$ million is recorded. This suggests that if the price of gas supply from Ghana fields is reduced it will have a significant impact on the cost of electricity. 26

28 4 TRANSMISSION SYSTEM OUTLOOK 4.1 State of Ghana National Interconnected Transmission System Ghana s high voltage transmission network transmits electricity at four voltage levels which are 330 kv, 225 kv, 161 kv and 69 kv. The transmission network consists of approximately 4,835.7 circuit kilometres (km) of high voltage lines connecting bulk generating plants at Akosombo, Kpong, Tema, Bui and Aboadze to sixty four (64) Bulk load substations across the nation. The network is made up of 219 km of 330 kv, 4,193.6 km of 161 kv and km of 69 kv lines. In addition, there is a 74.3 km single circuit 225 kv tie-line interconnecting the GRIDCo network with that of CIE (Compagnie Ivoirienne d Electricité) of Cote d Ivoire. The network also has a total transformer capacity of 4,498.5 MVA distributed across load centers within the nation. Furthermore, the National Interconnected Transmission System (NITS) has a total capacity of 636 MVAr in static capacitor banks installed, distributed across various substations such as Achimota, Mallam, Smelter, Winneba, Takoradi, Kumasi etc.; as well as a 40 MVAr Static Var Compensator (SVC) installed at Tamale substation. The capacitor banks and SVC provide reactive compensation on the power system, in order to minimize transmission losses and maintain good voltages across the NITS. The System Control Centre (SCC) in Tema is responsible for the dispatch (monitoring, coordination and control) of power system operations on the Ghana Power System as well as cross-border power exchanges with neighboring countries. SCC is equipped with an ABB Network Manager System (NMS), which is the main tool used to monitor and control operations on the Ghana power system. 4.2 Availability of Transmission Lines, Feeders and Substations All existing transmission lines, comprising of 219km of 330kV, 74.3km of 225kV, 4,193.6km of 161kV, and 138.8km of 69kV circuits are expected to continue to be in service to transmit the projected energy generation to customers across the power system. Maintenance work on transmission lines and substations are not expected to significantly affect power supply to customers except for single transformer substations and consumers served on single radial lines. With a total transformer capacity of 4,498.5 MVA and a projected peak load of 2,477 MW (at an average power factor of 0.9) the Transformer Utilization Factor (TUF) is 61 % for Most transformers in operation on the NITS are designed with a capability of 100% continuous loading (100% TUF). Therefore the projected TUF of 61% for 2016 suggests 27

29 there is adequate transformer capacity on the NITS for the supply of power under normal operating conditions. 4.3 System Analyses - Steady State Network analyses were carried out to evaluate the overall impact of the demand-supply scenario on the security and reliability of the transmission system. The analyses mostly based on the assumption of steady state conditions to determine transmission line loadings, substation bus voltages and losses across the transmission network. In particular, the analyses sought to investigate the following: Possible transmission line loading constraints to the secure and reliable power evacuation from the generating stations to load centres; Effect of nodal bus voltages on overall network stability; The ability of the entire power system to withstand a single contingency (i.e. outage) on a network element (e.g. transmission line, generator, transformer, etc.); Levels of reactive power generation from the generators; Adequacy of overall reactive power compensation within the NITS in keeping system voltages at normal levels; The projected overall transmission system losses during peak and off-peak periods. This way, the average annual transmission loss could be estimated. Security of generation schedule, to determine the optimal generation scheduling in order to achieve voltage stability and minimum losses. 4.4 Summary of System Analysis Results 1. With a projected peak demand of 2,477 MW for 2016, overall transmission system losses are projected to be averagely four percent (4%) of total energy generation. The losses are attributable to poor load power factors at customer end, non-optimal geographical distribution of generating plants as well as power evacuation via low capacity transmission lines in some portions of the network. 2. The analysis also shows poor voltages on the Kumasi bus (138kV).This is attributed to poor load power factor at the customer end. Not having dynamic voltage support on the bus, low voltages at Kumasi contribute significantly to system losses. 28

30 3. With a projected generation of 1,225 MW from the Tema generation enclave, the load flow analyses show overloads of 112% on the Volta Accra East Achimota transmission lines during normal operation condition. Increased power generation in Tema coupled with high peak demand in the capital will require the Volta-Achimota (V-H) corridor to operate above their thermal limits. A contingency on any line on the corridor could lead to a system disturbance. 4. The projected total power generation from the Aboadze generation enclave including the Ameri emergency power plant is 850 MW. The simulation shows that, the existing facility is capable of evacuating the projected total generation under normal system conditions. However, a contingency on any of the outgoing lines, the Takoradi-Tarkwa and Tarkwa Prestea lines results in overloading of adjacent lines and low bus voltages in the corridor. 5. To ensure stability of the grid, the minimum generation required to be in operated is as follows: 300 MW power generation from Aboadze and Three (3) Akosombo units (3x125MW) 4.5 Transmission System Constraints The Load Flow analysis shows that the transmission network has just enough capacity to transmit the projected power generation from all generation stations to the load centers during normal operating condition(s) for some sections of the networks. However, there are some critical lines for which a single contingency will put the power system in alert state, resulting in overloading of adjacent line circuits, low NITS voltages and in some cases, severe system disturbances. These are: lines in the Volta Accra East Achimota corridor; Achimota-Mallam line; Aboadze Tarkwa line; Tarkwa Prestea line; 330 kv Aboadze Volta line etc. Table 13 and Figure 6 show low voltage buses in Accra and Kumasi areas. Figures 7, 8 and 9 show the impact of a single contingency on the Volta - Achimota corridor on the stability of the network. Also, for customers served on radial lines (e.g. Esiama, Yendi, Akyempim, Zebila, Bawku) as well as those served from single transformer substations such as Esiama, Akosombo, Yendi, Kpong etc., an outage on the line (or transformer) would lead to an interruption in supply. 29

31 The simulation results further show low voltages in Kumasi and Accra zones as shown in the Table below. Table 13: Load Flow Results of Selected Bus Voltages 30

32 Figure 6: Load Flow Results of Selected Bus Voltages 31

33 Figure 7: Voltage Plot at Achimota and A3BSP for Loss of Volta-Achimota 161kV Line Figure 8: Frequency Plot for loss of Volta-Achimota 161kV Line 32

34 Figure 9: System Angle Spread Plot for Loss of Volta-Achimota 161kV Line Due to lack of redundancy in the network, it is difficult obtaining/granting outages for transmission equipment maintenance. This results in delays in carrying out scheduled maintenance work which could eventually lead to breakdown of equipment. 4.6 Recommended System Expansion & Upgrade to Address Network Constraints In order to address the above network constraints, we recommend the implementation of the following projects: Upgrading of transmission lines in the Volta Accra East Achimota corridor from 213 MVA to a 488 MVA, twin Tern ACSR 2x430 mm 2 line. This would increase the evacuation capacity from Tema generation hub to the load center of Accra. Especially, this is necessary to ensure the evacuation of generation from the new thermal power plants in Tema, namely Karpower (225 MW), Sunon-Asogli Phase-2 (180MW) and the Kpone Thermal Power Plant (KTPP MW). 33

35 Fast tracking the ongoing construction of Aboadze-Prestea-Kumasi 330kV line. This would improve upon bus voltages in Kumasi and adjacent substations and consequently reduce overall system losses. Upgrade of Achimota Mallam 161 kv transmission line conductor from 170 MVA to 488 MVA, twin Tern ACSR 2x430 mm 2 line to improve bus voltages at Achimota and adjacent substations. It would also reduce overall transmission losses and lines loading on the NITS. This project has already been awarded on contract. Construction of A4BSP 330kV substation with a 161kV, double circuit twin bundle (364x2 MVA) link to Mallam BSP. This would increase the reliability of supply to Accra and increase transfer capacity between the generation hub of Aboadze and Tema to the load Centre of Accra. 34

36 ELECTRICITY SUPPLY CHALLENGES The following are the major challenges anticipated which can adversely impact on reliability of supply Hydro Risk. Because of the low elevations at Akosombo 3 units will have to be operated throughout the year to avoid a situation where only 2 units operation can be supported. Hitherto the Akosombo hydro power station was normally used to make up for generation outages. In 2016 Akosombo cannot be increased to above 3 units to make up for thermal outages. This poses a challenge for the power system. Consequently thermal plant outages could lead to supply challenges. Fuel Supply. Currently 200MW installed capacity at Sunon Asogli together with other plants (e.g. Sunon Asogli Phase-II) run solely on natural gas, hence any major disruption in gas supply will render these capacities inoperable with its attendant impact on power supply reliability. In 2015 non-availability of funds to purchase fuel was one of the major challenges to providing reliable power supply. Hence availability of the needed funds (an estimated average of US$113 million/month) to purchase the needed quantities of fuel and on time is critical to ensuring reliable power supply in Supply Reliability. To ensure reliability of supply, it is recommended to keep operating reserves of 25% at all times in 2016 and beyond. In 2015 the Power System was operated with a very low reserve margin and hence thermal plant outages (maintenance and forced) led to inadequate supply. Power system dispatch in January and February of 2016 could be challenging due to possible supply deficit as a result of the timing of additional generation projects. Power Evacuation. Inadequacy in transmission capacity which could lead to transmission line overloads in some portions of the network. Insufficient reactive power compensation which could lead to poor customer supply voltage in areas such as Kumasi, Accra and some parts of the western region. Inability of the transmission network to withstand some single line/transformer contingencies and the N-1 criterion. A contingency on any of the following radial lines and single transformer stations would result in outage to consumers: 35

37 Radial lines o Tamale Yendi o Takoradi Esiama o Bogoso Akyempim o Bolga - Zebila o Zebila Bawku, etc. Single Transformer Stations o Akosombo, Kpong GS, Yendi, Esiama etc. Challenges in securing outages required to upgrade the network and for carrying out planned maintenance work. 36

38 ELECTRICITY SUPPLY OUTLOOK Thermal power generation projects usually take between months to construct depending on the type of technology being deployed. Due to the long lead time for power generation projects, this section provides an outlook for generation requirements for the next five years ( ) to enable the adequate measures to be put in place to ensure that power supply security is maintained. 6.6 Projected Demand Outlook ( ) Projected electricity demand over the period is based on GRIDCo s load forecast for It is necessary to highlight that VALCO is assumed to increase from 1 potline operation in 2016 to 2 potlines in 2017, 3 potlines in 2018 and from 2019, the full 5 potline operation is assumed. Total electricity consumption of the Ghana power system including exports to Togo, Benin and Burkina Faso and Mali (from 2019) is projected to increase from 16,798 GWh in 2016 to 27,344 GWh in 2021 at a Compound Annual Growth Rate (CAGR) of 10.2%. The system peak demand is projected to increase from 2,476 MW in 2016 to 3,886 MW in The summary of the electricity demand (GWh and MW) are shown in Tables 14 and 15. Table 14: Projected Electricity Demand in GWh: Forecast Demand in GWh Total Domestic 14,458 16,271 17,408 18,336 18,869 19,928 VALCO 620 1,240 1,875 3,125 3,125 3,125 Exports 1,081 1,161 1,678 2,662 3,007 3,303 Transmission Losses Total Demand (GWh) 16,798 19,379 21,746 25,028 25,938 27,344 Table 15: Projected Electricity Demand in MW: Forecast Demand (MW) Domestic 2,144 2,299 2,466 2,600 2,677 2,834 VALCO Exports Transmission Losses Total Projected Demand (MW) 2,476 2,731 3,084 3,538 3,675 3, Projected Supply Outlook ( ) 37

39 The power supply outlook was prepared considering the existing and committed generation. The generation gap was then determined using plants of 340 MW modules and also ensuring that generation reserve margin does not fall below 25% in any given year Existing Generation Existing generation capacity remains the same as assumed for the 2016 supply. However the following key assumptions for hydro power supply were made: Akosombo & Kpong GS. Provision was also made for the recovery of the Akosombo reservoir. 4 units were assumed in 2017, 5 units in 2018 and From 2020 all the 6 units are expected to be available to support peak demand. Akosombo & Kpong generation are assumed to be 4100 GWh in 2017 and 4800 GWh in It is assumed that from 2019 the firm Akosombo and Kpong supply of 5300 GWh would be maintained. Bui Hydro Power Station. Bui hydro is assumed to produce about 760 GWh of electricity/year from Bui is assumed to provide 220 MW of generation capacity to support peak demand Committed Generation There are a number of projects that are under discussion and may be developed. However it is unclear whether or not any of those projects will be commissioned. Therefore in this analysis only projects under construction were considered. As a result apart from new generation projects considered for the 2016 power supply, two new projects were also considered as committed projects as follows: 180 MW Sunon-Asogli (Phase 2 Stage 2) - This is the second phase of the 360 MW combined cycle project. 180 MW was assumed to be available in 2016 and the second 180 MW is assumed to be online in MW Cenpower Project Construction for this project has commenced and based on the project timeline, the plant should be commissioned by fourth quarter of However in this analysis the plant is assumed to be available from January Additional Generation Requirement Based on the existing and committed generation and the assumptions on hydro as well as generation reserve margin requirements, the incremental generation capacity requirement over the period is projected to be as shown in Table 16: 38

40 Table 16: Incremental Generation Capacity Requirement in MW: Incremental Generation Requirement (MW) Based on the expected generation and additional generation requirement if the new projects come online as planned from the power system would meet the minimum generation capacity reserve margin of 25% from Figure 10: Demand/Supply Outlook